Method and product for use of guar powder in treating subterranean formations

ABSTRACT

A method of treating a subterranean formation using a well-treating fluid is provided, the subterranean formation penetrated by a wellbore, the method comprising preparing the well-treating fluid by admixing a fast-hydrating high-viscosity guar powder to a hydrating liquid to prepare the well-treating fluid; hydrating the guar powder; admixing a cross-linker to the well-treating fluid; and introducing the well-treating fluid to the wellbore at a temperature and a pressure sufficient to treat the subterranean formation. A product is also provided comprising a well-treating fluid for use in treating subterranean formations with the well-treating fluid comprising a hydrating liquid; a gelling agent, the gelling agent comprising a fast-hydrating high-viscosity guar powder; and a cross-linker.

RELATED APPLICATION(S)

[0001] This application is a continuation-in-part of co-pending,commonly assigned U.S. patent application IMPROVED METHOD AND PRODUCTFOR USE OF GUAR POWDER IN TREATING SUBTERRANEAN FORMATIONS, Ser. No.10/146,326, filed May 14, 2002, which is a continuation-in-part ofco-pending, commonly assigned U.S. patent application GUAR GUM POWDERPOSSESSING IMPROVED HYDRATION CHARACTERISTICS, Ser. No. 09/991,356,filed Nov. 19, 2001. Application Ser. No. 09/991,356 is a division ofco-pending, commonly assigned U.S. patent application IMPROVED HYDRATIONOF GUAR GUM POWDER, Ser. No. 09/501,559, filed Feb. 9, 2000.

TECHNICAL FIELD OF THE INVENTION

[0002] This application relates generally to the field of subterraneandrilling and more specifically to the use of guar powder in “on-the fly”treatment of subterranean formations.

BACKGROUND OF THE INVENTION

[0003] Oil and natural gas (“gas”) are typically found in subterraneanformations. To obtain the oil or gas, the subterranean formation must bepenetrated, thereby allowing the oil or gas to be produced through awellbore.

[0004] In standard operations, a wellbore is drilled from the surface tothe subterranean formation. The wellbore penetrates the subterraneanformation, which allows the oil or gas to flow from the subterraneanformation to the surface via the wellbore. For the oil or gas to escapethe subterranean formation and flow to the wellbore, the oil or gas musthave a sufficiently unimpeded path from the subterranean formation tothe wellbore. Typically, this path is through the formation rock, whichusually comprises sandstone or carbonates. For the formation rock toenable a sufficient oil or gas flow, the formation rock must have asufficient number of pores with a size and connectivity to provide theproper conduit for the oil or gas.

[0005] Frequently, the oil or gas is not able to escape the subterraneanformation and flow through the wellbore, or oil or gas may only escapein less than optimal amounts. For instance, damage to the subterraneanformation may plug the pores of the formation rock. Damage may be causedby fluids that were injected into the wellbore during drilling of thewellbore or injected during treatments of the subterranean formation.Typically, portions of these fluids may remain in the wellbore after theinjection and may dehydrate and take solid form over time. Thesedehydrated fluids may then coat the wellbore or pores of the formationrock, which may result in stopping or reducing the flow of gas or oil.Additional reasons for reduced flow of oil or gas include pores withless than optimal size or number. With such pores, the formation rockmay have a low permeability to the flow of oil or gas.

[0006] One method for increasing the flow of oil or gas from thesubterranean formation is to “stimulate” the subterranean formation.Stimulation of the subterranean formation involves fracturing thesubterranean formation, thereby causing cracks that extend from thewellbore to the subterranean formation. Typically, this fracturing ofthe subterranean formation involves injecting a well-treating fluid thatcomprises chemicals in gel form through the wellbore and to theformation at pressures sufficient to fracture the formation. Thestandard components of the gelled well-treating fluid comprise a carrierfluid, a polymer, a cross-linker, and a propping agent. Thewell-treating fluid is inserted into the wellbore at a temperature andpressure sufficient to stimulate one or more fractures of the surface ofthe subterranean formation. Typically, the gel is inserted in 17 lb (8kg) or 30 lb (14 kg) injections. After the fracture is sufficientlyopen, the well-treating fluid flows into the fracture and deposits thepropping agent. A breaking agent is then introduced to the wellbore, andthe breaking agent breaks the gelled well-treating fluid into a thinfluid, which allows for its removal from the wellbore. Alternatively,the well-treating fluid may further comprise a delayed breaking agentthat breaks the well-treating fluid at a time after the fracture of thesubterranean formation. After the well-treating fluid is broken andremoved, the propping agent remains in the fractures. The propping agentkeeps the fractures from closing after the broken well-treating fluid isremoved. The propping agent also increases the flow of oil or gasthrough the fracture by providing channels through which the oil or gasmay flow to the wellbore. Alternatively, the gelled well-treating fluidthat stimulates the fracture of the formation may not comprise anypropping agent. Instead, the propping agent is not added to thewell-treating fluid until after the subterranean formation is stimulatedand thereafter is introduced in to the fractures.

[0007] High viscosity is an important aspect to these cross-linked gels.For instance, the width of the fracture may be proportional to theviscosity of the fracturing fluid. In addition, a high viscosity enablesthe well-treating fluid to transport the propping agents without thepropping agents settling out of the well-treating fluid.

[0008] The standard polymer in the well-treating fluid is guar gum. Guargum comes from a plant that is grown primarily in India and Pakistan,although other climates are also friendly to its cultivation. Guar is alegume-type plant that produces a pod, much like a green bean. In thepod, there are seeds that, upon heating, split open, exposing theendosperm and meal. The exposed endosperm contains a polymer that is ofgreat use for thickening industrial and commercial fluids. The polymeris a polysaccharide material known as polygalactomannan. This materialdevelops a high viscosity via hydration of the fluid to be thickened.

[0009] The original process for making the gelled well-treating fluidinvolved an operator mixing bags of guar powder with water in a hopperand then transferring the mixture to a storage tank. The guar powder wasallowed to hydrate in the storage tank for a period of time thattypically spanned several hours. After the mixture was sufficientlygelled, the gelled fluid was then pumped into the wellbore. One seriousdrawback to this process was the large expense involved in such a largeamount of time expended to hydrate the guar powder. In addition, thelarge amounts of guar powder that were required to have a sufficientviscosity added significantly to the cost in producing the oil or gas.

[0010] To increase efficiency over this original process, the industrydeveloped an “on-the-fly” process to make the gelled well-treatingfluid. In this process, a liquid slurry comprising guar powder, acarrier fluid, and suspending agents is prepared remote from thewellbore site. The carrier fluid typically comprises a diesel fuel ormineral oil. The suspending agents, which are used to suspend theslurry, are inorganic and non-soluble in water. This liquid slurry isthen taken to the wellbore site and mixed in hydration tanks with waterto form the gelled well-treating fluid. These hydration tanks are alsocalled on-the-fly hydration units. In these on-the-fly hydration units,the guar powder in the liquid slurry is allowed to hydrate for aboutseven to ten minutes. A cross-linker and any other additives are thenadded to the liquid slurry and then the gel is introduced to thewellbore.

[0011] U.S. Pat. No. 4,336,145 (the “'145 Patent”) also discloses apre-prepared liquid slurry, but instead discloses water as the carrierfluid. In the '145 Patent, the gel is prepared by suspending the polymerin water by using an inhibitor to retard the hydration rate of thepolymer. When the gel is then later mixed with additional water, theinhibitor reverses and the hydration of the polymer commences.

[0012] It is highly advantageous to have a well-treating fluid and amethod for using the well-treating fluid that uses a fast-hydrating andhigh-viscosity polymer. The time involved in preparing the well-treatingfluid for introduction to the wellbore is directly related to theincreased efficiency, and, thereby, reduced expenses, in the productionof oil and gas. The liquid slurry process has reduced the several hourstime required of the original process. However, the liquid slurry is apre-prepared mixture. The time and effort involved in preparing theliquid slurry decreases the cost efficiency of the production. A furtherdrawback of the liquid slurry process includes the introduction of thenon-soluble suspending agents to the wellbore, where the non-solublesuspending agents are not broken by the breaking agent. Therefore, thesesuspending agents remain in the fractures along with the propping agentsand may lead to clogging of the pores, which may reduce or stop the flowof the oil or gas. In addition, the large amount of suspending agentrequired to suspend the slurry increases the cost of the productionoperation. Moreover, the suspending agents may interfere withcross-linking of the polymer. Drawbacks also include environmentalconcerns and additional cost increases. For instance, the inhibitorintroduced to the wellbore in the '145 patent presents harmful chemicalsto the environment and the removal of such harmful chemicals posesstorage problems. The added cost of storing and removing these chemicalsand the initial cost of using these chemicals also decreases the costefficiency of the production. In addition, the use of diesel in theliquid slurry is also potentially harmful to the environment. The largeamount of diesel used may be cost prohibitive due to the initial cost ofusing the diesel and the added cost in removing the diesel. A furtherdrawback includes the amount of polymer or guar powder that must be usedto have a viscosity high enough to transport the propping agent. Toincrease the viscosity of the gelled well-treating fluid, operatorstypically add additional guar powder or polymer to attain the desiredviscosity, which increases costs.

[0013] Consequently, there is a need for a well-treating fluid thatcomprises a high-viscosity and fast-hydrating polymer. There is a needfor a method of producing and using such a well-treating fluid. Further,there is a need for a way to minimize the amount of polymer used inpreparing a well-treating fluid. In addition, there is a need forreducing the amount of harmful pollutants introduced to the environmentduring the treatment of a subterranean formation.

SUMMARY OF THE INVENTION

[0014] These and other needs in the art are addressed in various aspectsof the present invention. In one aspect, an inventive method of treatinga subterranean formation using a well-treating fluid is provided, thesubterranean formation penetrated by a wellbore, the method comprising(A) preparing the well-treating fluid by admixing a fast-hydratinghigh-viscosity guar powder to a hydrating liquid to prepare thewell-treating fluid; (B) hydrating the guar powder; (C) admixing across-linker to the well-treating fluid; and (D) introducing thewell-treating fluid to the wellbore at a temperature and a pressuresufficient to treat the subterranean formation.

[0015] In another aspect of the present invention, a well-treating fluidfor use in treating subterranean formations is provided, thewell-treating fluid comprising a hydrating liquid; a gelling agent, thegelling agent comprising a fast-hydrating high-viscosity guar powder;and a cross-linker.

[0016] In a third aspect of the present invention, a well-treating fluidfor use in treating subterranean formations is provided, the treatmentcomprising a fracture stimulation, the well-treating fluid comprising ahydrating liquid; a gelling agent, the gelling agent comprising afast-hydrating high-viscosity guar powder; a cross-linker; and apropping agent.

[0017] In a fourth aspect of the present invention, a well-treatingfluid for use in treating subterranean formations is provided, thetreatment comprising a fracture stimulation, the well-treating fluidcomprising a hydrating liquid; a gelling agent, the gelling agentcomprising a fast-hydrating high-viscosity guar powder; a cross-linker,the cross-linker comprising a cross-linking agent and a delaying agent;a delayed breaking agent; and a propping agent.

[0018] In a fifth aspect of the present invention, a method of treatinga subterranean formation using a well-treating fluid is provided, thesubterranean formation penetrated by a wellbore, the method comprising(A) preparing the well-treating fluid by admixing a fast-hydratinghigh-viscosity guar powder to a hydrating liquid to prepare thewell-treating fluid; (B) hydrating the guar powder; (C) admixing across-linker and a delayed breaking agent to the well-treating fluid;and (D) introducing the well-treating fluid to the wellbore at atemperature and a pressure sufficient to treat the subterraneanformation.

[0019] In a sixth aspect of the present invention, a method ofperforming a fracture treatment in a subterranean formation using awell-treating fluid is provided, the subterranean formation penetratedby a wellbore, the method comprising (A) preparing the well-treatingfluid by admixing a fast-hydrating high-viscosity guar powder to ahydrating liquid to prepare the well-treating fluid; (B) hydrating theguar powder; (C) admixing a cross-linker and a propping agent to thewell-treating fluid; and (D) introducing the well-treating fluid to thewellbore at a temperature and a pressure sufficient to stimulate thefracture treatment of the subterranean formation.

[0020] In a seventh aspect of the present invention, a method ofperforming a fracture treatment to a subterranean formation using awell-treating fluid is provided, the subterranean formation penetratedby a wellbore, the method comprising (A) preparing the well-treatingfluid by admixing a fast-hydrating high-viscosity guar powder to ahydrating liquid to prepare the well-treating fluid; (B) hydrating theguar powder; (C) admixing a cross-linker, a propping agent, and adelayed breaking agent to the well-treating fluid, wherein thecross-linker comprises a delaying agent and a cross-linking agent, andwherein the cross-linker is disposed to delay the cross-linking untilafter the well-treating fluid is introduced to the wellbore; (D)introducing the well-treating fluid to the wellbore at a temperature anda pressure sufficient to stimulate the fracture treatment of thesubterranean formation; and (E) breaking the well-treating fluid withthe delayed breaking agent, the delayed breaking agent disposed to delaybreaking of the well-treating fluid until after stimulation of thefracture treatment.

[0021] The foregoing has outlined rather broadly many of the featuresand technical advantages of the present invention in order that thedetailed description of the invention that follows may be betterunderstood. Additional features and advantages of the invention will bedescribed hereinafter which form the subject of the claims of theinvention. It should be appreciated by those skilled in the art that theconception and the specific embodiments disclosed may be readilyutilized as a basis for modifying or designing other structures forcarrying out the same purposes of the present invention. It should alsobe realized by those skilled in the art that such equivalentconstructions do not depart from the spirit and scope of the inventionas set forth in the appended claims.

BRIEF DESCRIPTION OF THE DRAWING

[0022] For a more complete understanding of the present invention, andthe advantages thereof, reference is now made to the followingdescriptions taken in conjunction with the accompanying drawing, inwhich:

[0023] the drawing illustrates a processing unit for well-treatingfluids.

DETAILED DESCRIPTION OF THE INVENTION

[0024] The accompanying drawing illustrates a process for on-the-flymanufacture of well-treating fluids in which a trailer 10 supportsprocess equipment 15. The process equipment 15 comprises a hydraulicpower pack 20, chemical additives tanks 30, a polymer tank 40, and ahydration unit 50. The hydraulic power pack 20 provides power to theother process equipment 15. The chemical additives tanks 30 comprisechemical storage tanks that store and supply the chemical additives tothe hydration unit 50. The chemical additives that are stored in thesetanks may comprise cross-linking agents, breaking agents, delayingagents, buffer solution additives, and/or any other suitable additivesfor admixing to the hydration unit 50.

[0025] The polymer tank 40 contains the polymers for adding to thehydration unit 50 in the preparation of the well-treating fluid. Thepolymer that is stored in the polymer tank 40 and used in preparing thewell-treating fluid of various illustrative embodiments of the presentinvention is the fast-hydrating high-viscosity guar powder disclosed inco-pending, commonly assigned U.S. patent applications with Ser. No.09/991,356 (the “'356 application”) and Ser. No. 09/501,559 (the “'559application”) of which this invention is a continuation-in-partapplication. The '356 application and the '559 application are herebyincorporated by reference in their entirety. The polymer that is used inpreparing the well-treating fluid may also comprise a de-polymerizedfast-hydrating guar powder, derivatives of the de-polymerizedfast-hydrating guar powder and derivatives of the fast-hydratinghigh-viscosity guar powder. Such derivatives may comprise hydroxy propylguar powder, carboxy methyl guar powder, and carboxy methyl hydroxypropyl guar powder. The fast-hydrating high-viscosity guar powder isstored in the polymer tank 40 in powder form.

[0026] The hydration unit 50 serves as a storage and mixing unit for thepreparation of the well-treating fluid. In the hydration unit 50, theguar powder is hydrated with a hydrating liquid and then mixed with thechemicals from the chemical additives tanks 30 by an agitator 60. A pump70 pumps the hydrating liquid from a water supply to the hydration unit50. An operator on an operator platform 90 oversees the operation of theprocess equipment 15.

[0027] The following describes an exemplary illustrative embodiment ofthe present invention as illustrated. The trailer 10 is located near awellbore (not illustrated). The operator turns on the power of thehydraulic power pack 20 so that the other process equipment 15 may thenbe supplied with power. Hydrating liquid from the water supply issupplied to the hydration unit 50 by the pump 70. The hydrating liquidmay comprise fresh water, brine, or any other suitable liquid that doesnot adversely react with other components of the well-treating fluid.After a certain amount of hydrating liquid is added to the hydrationunit 50, fast-hydrating high-viscosity guar powder from the polymer tank40 is added to the hydration unit 50. The agitator 60 mixes the guarpowder with the hydrating liquid. The guar powder is added to thehydrating liquid in an amount that may comprise about 0.15 to about 0.30percent by weight of the hydrating liquid. The guar powder is notlimited to this percent by weight of the hydrating liquid but, invarious alternative illustrative embodiments, may alternatively compriseanywhere from about 0.05 to about 1.0 percent by weight of the hydratingliquid. The guar powder is allowed to hydrate in the hydrating fluid. Inaddition, the guar powder and hydrating liquid mixture form into a gel.The guar powder may be allowed to hydrate in the hydrating fluid for atime period up to about 5 minutes, which results in about a 90 percenthydration rate of the guar powder. Alternatively, the guar powder may beallowed to hydrate for a longer or a shorter period of time, dependingon the circumstances.

[0028] After the guar powder hydrates in the hydration unit 50, across-linker may be admixed to the guar powder and water mixture to formthe well-treating fluid. The cross-linker may comprise a cross-linkingagent and a delaying agent. The cross-linking agent and delaying agentmay be mixed at the trailer 10 or remote from the trailer 10. Thecross-linking agent may comprise from about 20.0 to about 35.0 percentby weight of the guar powder. Alternatively, the cross-linking agent maycomprise from about 10.0 to about 40.0 percent by weight of the guarpowder. The delaying agent may comprise from about 2.0 to about 10.0percent by weight of the guar powder. Alternatively, the delaying agentmay comprise from about 0.5 to about 25.0 percent by weight of the guarpowder. Examples of available cross-linking agents include zirconium,titanium, chromium, aluminum, antimony, iron, zinc, borate, boron, andthe like. Examples of available delaying agents include glycerol,erythritol, threitol, ribitol, arabinitol, xylitol, allitol, altritol,sorbitol, mannitol, dulcitol, iditol, perseitol, and the like. Thecross-linking agent bonds molecules of the guar together by attaching tothe hydroxyl groups of the guar. By such cross-linking, the viscosity ofthe well-treating fluid may be increased. The delaying agents in thecross-linker delay the cross-linking of the guar molecules until thewell-treating fluid is down the wellbore, thereby maintaining a lowerviscosity in the well-treating fluid while pumping into the wellbore.The delaying agents may delay the cross-linking from several minutes toseveral hours, depending on the requirements of the situation. Bydelaying the cross-linking, the amount of pressure needed to pump thewell-treating fluid from the hydration unit 50 to the wellbore may besubstantially decreased. Alternatively, the cross-linker may notcomprise a delaying agent. Instead, the delaying agent may be admixed tothe guar powder and hydrating liquid mixture before the cross-linkingagent is admixed to the mixture. In various alternative embodiments, thedelaying agent may not be admixed to the well-treating fluid.Consequently, the cross-linking agent may immediately begin thecross-linking of the guar upon its addition to the well-treating fluid.

[0029] After admixing the cross-linker in the hydration unit 50 to formthe well-treating fluid, a delayed breaking agent, which may be storedin the chemical additive tanks 30, may be admixed to the well-treatingfluid in the hydration unit 50. The delayed breaking agent may beadmixed to the well-treating fluid in an amount comprising from about0.01 to about 2.5 percent by weight of the hydrating liquid in thewell-treating fluid. The amount of the delayed breaking agent may beadjusted, depending on the required breaking time of the gelledwell-treating fluid. Delayed breaking agents that may be used includealkali metal chlorites, hypochlorites, calcium hypochlorites, and anyother suitable breaking agent. Such delayed breaking agents aredescribed in U.S. Pat. No. 5,413,178, issued on May 9, 1995; U.S. Pat.No. 5,669,446, issued on Sep. 23, 1997; and U.S. Pat. No. 5,950,731,issued on Sep. 14, 1999, the entire disclosures of which areincorporated by reference. Alternatively, the delayed breaking agent maynot be admixed to the well-treating fluid before the well-treating fluidis introduced to the wellbore. Instead, the delayed breaking agent maynot be introduced to the wellbore until after the well-treating fluidhas completed the treatment of the subterranean formation.

[0030] After the delayed breaking agent is admixed to the well-treatingfluid in the hydration unit 50, the well-treating fluid may be removedfrom the hydration unit 50, and a propping agent may be admixed andsuspended in the well-treating fluid. The propping agent may be admixedto the well-treating fluid in an amount comprising from about 1 pound(0.45 kg) to about 10 pounds (4.5 kg) of propping agent per gallon (4liters) of well-treating fluid. This concentration may be increased ordecreased, depending on the circumstances. Propping agents that may beused include sand, tempered glass beads, aluminum pellets, sinteredbauxite, nylon pellets, and any other suitable propping agent.Alternatively, the propping agent may be admixed along with thecross-linker, which may comprise the cross-linking agent and delayingagent, and simultaneously suspended. In other alternative embodiments,the propping agent may be admixed along with a cross-linker, withoutdelaying agents, and simultaneously suspended.

[0031] The on-the-fly process from the hydration of the guar powder inthe hydrating liquid to the mixing of the well-treating fluid with thesuspended propping agent may take place in a matter of minutes, with thehydration of the guar powder taking place in a period of time up toabout 5 minutes with about a 90 percent hydration rate. The process maytake more or less time, depending on the circumstances. After admixingthe propping agent, the well-treating fluid with the suspended proppingagent may then be introduced into the wellbore in 17 lb (8 kg) gelincrements. Alternatively, the well-treating fluid may be introduced tothe wellbore in 30 lb (14 kg) gel increments or in any other suitableincrements. By these 17 lb (8 kg) gel increments, the well-treatingfluid may stimulate the fracture treatment of the subterraneanformation. After the subterranean formation is fractured, thewell-treating fluid may deliver the propping agents to the fractures ofthe subterranean formation. Thereafter, the delayed breaking agent maybreak the gelled well-treating fluid into a thin liquid. The brokenwell-treating fluid may then be removed from the wellbore. In variousalternative embodiments, the propping agent may not be admixed to thewell-treating fluid until after the well-treating fluid has stimulatedthe fracture of the subterranean formation. Upon the fracture, thepropping agent may be admixed to the well-treating fluid, and thewell-treating fluid with the suspended propping agent may be introducedto the wellbore, through which process the propping agent may bedeposited in the fractures.

[0032] The preparation of the well-treating fluid and its introductionto the wellbore may be undertaken in ambient temperatures, whichtypically range from about 70 degrees F. (21° C., 294 K) to about 120degrees F. (49° C., 322 K), and may have similar results in viscositiesand hydration rates in temperatures lower and/or higher than thestandard ambient temperatures. The temperatures in the wellbore and nearthe subterranean formation typically range between about 120 degrees F.(49° C., 322 K) to about 350 degrees F. (232° C., 450 K), which is alsoa suitable temperature range for various illustrative embodiments of thepresent invention.

[0033] In various alternative embodiments, the well-treating fluid maycomprise additional components that may be admixed to the well-treatingfluids described above. For example, conventional additives such as pHcontrol agents, bactericides, clay stabilizers, surfactants, and thelike, which do not interfere with the other components, or adverselyaffect the treatment, may also be used.

[0034] In addition to the stimulation of subterranean formationfractures, various illustrative embodiments of the present invention maybe used in other treatments that include well completion operations,fluid loss control treatments, treatments to reduce water production,drilling operations, and any other suitable treatments.

[0035] To further illustrate various illustrative embodiments of thepresent invention, the following examples are provided.

EXAMPLE 1

[0036] TABLE 1 illustrates the hydration rate performance of an improvedfast-hydrating high-viscosity guar powder (as disclosed in the '356 and'559 patent applications) over conventional guar powder. New Guar 1, NewGuar 2, New Guar 3, and New Guar 4 represent products produced accordingto the '356 and '559 patent applications. The Old Guar represents a guarpowder product prepared under the conventional standard process. In thisexample, 2.4 g of guar powder was mixed in 500 ml of tap water by aWaring blender for one minute at 2800 rpm. The resulting mixturecorresponds to a 40 lb (18 kg) gel. Thereafter, about 350 ml of thismixture was measured at 300 rpm by a FANN-35 viscometer. The resultingviscosities were measured at varying time increments, and the resultsfor each guar product are illustrated in TABLE 1. As shown in TABLE 1,the New Guar 1, New Guar 2, New Guar 3, and New Guar 4 result in anincrease in viscosity over the Old Guar. In addition, these resultsindicate that the New Guar 1, New Guar 2, New Guar 3, and New Guar 4hydrate at a faster rate than the Old Guar, with the New Guar 1, NewGuar 2, New Guar 3, and New Guar 4 exhibiting about a 90 percenthydration rate at 5 minutes. TABLE 1 New Time in New Guar 1 New Guar 2Guar 3 New Guar 4 Old Guar Minutes (cps) (cps) (cps) (cps) (cps)  333-35 42-44 25-28 29-32 22-24  5 35-39 44-46 28-30 32-34 24-26 15 39-4146-48 31-34 35-37 28-30 60 42-44 48-50 35-37 38-40 33-36

EXAMPLES 2-10, 13, 19 AND 20

[0037] In these examples, different amounts of New Guar 1, New Guar 2,New Guar 3, New Guar 4 and Old Guar were hydrated with water and mixedwith cross-linking agents. These examples illustrate a procedure foron-the-fly making of the gelled well-treating fluid. TABLE 2 illustratesthe resulting viscosities of the different guar mixtures of theexamples. TABLE 2 10 20 30 40 50 60 Example Gel Cross-linker MIN. MIN.MIN. MIN. MIN. MIN. No. Product (lbs) (mls) (cps) (cps) (cps) (cps)(cps) (cps)  2 Old Guar 30 0.2 237 343 384 422 483 425  3 Old Guar 300.3 237 365 429 490 528 542  4 Old Guar 30 0.35 223 336 415 493 542 551 5 New Guar 1 30 0.35 455 563 626 763 957 914  6 New Guar 1 30 0.4 403516 657 687 830 1027  7 New Guar 1 30 0.45 461 680 841 1007 1007 1166  8New Guar 1 30 0.5 756 818 923 1103 1174 1370  9 New Guar 1 30 0.6 821956 1337 1259 1303 1374 10 New Guar 1 17 0.45 225 237 254 279 295 315 11New Guar 1 17 1.25 254 263 322 334 339 342 12 New Guar 2 17 1.5 380 440480 500 510 525 13 New Guar 2 17 0.45 380 395 409 430 415 448 14 NewGuar 2 17 0.45 345 355 385 370 390 387 15 New Guar 2 17 0.45 370 360 390385 400 420 16 Old Guar 30 2.0 774 729 691 727 768 703 17 Old Guar 171.25 N/A N/A N/A N/A N/A N/A 18 New Guar 2 17 1.5 300 315 335 320 340350 19 New Guar 3 30 0.35 280 365 450 525 600 675 20 New Guar 4 30 0.35320 400 510 585 650 755

[0038] The guar powder was mixed with 150 ml of tap water. To make a gelthat corresponds to a 17.0 lb (8 kg) gel, about 0.3 g of the guar powderwas used to mix in the tap water. To make a gel that corresponds to a30.0 lb (14 kg) gel, about 0.53 g of the guar powder was used to mix inthe tap water. The guar powder and water were shaken for about 30seconds to mix them together. Thereafter, about 0.2 ml of pH buffersolution was added into the mixture and shaken for about 10 seconds. Across-linking agent was added to the mixture and then shaken for about20 more seconds. Within 1 minute, the resulting cross-linked gel wasthen placed in a FANN-50 rheometer for viscosity measurements. In therheometer, a B5 extended bob was used, and the measurements were takenat 95 rpm and at 140 degrees F. (60° C., 333 K). The viscositymeasurements for 10 minute intervals and the amounts of cross-linkerused are depicted in TABLE 2. From the results shown in TABLE 2, it maybe seen that the New Guar 1, New Guar 2, New Guar 3, and New Guar 4exhibit much higher viscosities than the Old Guar. In addition, the NewGuar 1, New Guar 2, New Guar 3, and New Guar 4 powders maintain theirviscosities and gelled form over time.

EXAMPLES 11, 12, 16, AND 17

[0039] Examples 11, 12, and 17 illustrate a procedure for on-the-flymaking of a 17.0 lb (8 kg) gel. In these examples, several times morecross-linking agents were admixed to the water than in the previousexamples. The results are also shown in TABLE 2.

[0040] In these examples, 1.02 g of guar powder was hydrated in 500.0 mlof water for about 30 minutes in a Waring blender at about 1200 rpm. Aborate cross-linking agent was then added to the fluid and further mixedfor about two minutes. The resulting cross-linked gel was then placed ina FANN-50 rheometer for viscosity measurements. In the rheometer, a B5extended bob was used, and the measurements were taken at 95 rpm and at140 degrees F. (60° C., 333 K). The viscosity measurements for 10 minuteintervals and the amounts of cross-linker used are shown in TABLE 2.From the results shown in TABLE 2, it may be seen that the New Guar 1and New Guar 2 exhibit much higher viscosities than the Old Guar, whichdid not even exhibit any measurable viscosity. Indeed, Example 17 showsthat no cross-linking takes place in using the Old Guar to make a 17.0lb (8 kg) gel according to various illustrative embodiments of thepresent invention, even with 1.25 ml of borate used to cross-link.

[0041] Example 16 illustrates the making of a 30.0 lb (14 kg) gel usingthe Old Guar and the on-the-fly procedure described above. Using 2.0 mlof borate to cross-link, Example 16 exhibits a measurable viscosity andshows that cross-linking took place. For the sake of comparison, the17.0 lb (8 kg) gel of Example 17 also used the Old Guar and the sameprocedure as Example 16 but did not exhibit any measurable viscosity.From the results of Examples 11, 12, 16, and 17, it may be seen that theuse of the New Guar 1 and New Guar 2 allows for a measurable viscosityby the use of a 17.0 lb (8 kg) gel in the above procedure, whereas useof the Old Guar allows for a measurable viscosity by the use of a 30.0lb (14 kg) gel in the above procedure but not by the use of a 17.0 lb(14 kg) gel.

EXAMPLE 14

[0042] In this example, the New Guar 2 was used in the liquid slurryform of the prior art. The results are also shown in TABLE 2.

[0043] A liquid slurry was made using a 48/50 ratio of New Guar 2 toDiesel No. 2 and about 1.45 ml of this liquid slurry was mixed withabout 150 ml of tap water and shaken for about 30 seconds. Thereafter,about 0.2 ml of pH buffer solution was added into the mixture and shakenfor about 10 seconds. A cross-linking agent was added to the mixture andthen shaken for about 20 more seconds. The resulting cross-linked gelwas then placed in a FANN-50 rheometer for viscosity measurements. Inthe rheometer, a B5 extended bob was used, and the measurements weretaken at 95 rpm and at 140 degrees F. (60° C., 333 K). As shown in TABLE2, the liquid slurry produces a lower viscosity than the on-the-fly gelusing the New Guar 2 powder. For the sake of comparison, example 13 usedthe same New Guar 2 powder and the same amount of cross-linking agentbut had a higher resulting viscosity.

EXAMPLE 15

[0044] In this example, about 0.3 g of the New Guar 2 powder was mixedwith 150 ml of tap water in a homogenizer with an open disc for about 30seconds, which yields a mixture that is comparable to a 17.0 lb (8 kg)gel. Thereafter, about 0.2 ml of pH buffer solution was added into themixture and mixed for about 10 seconds in the homogenizer. Across-linking agent was added to the mixture and then mixed in thehomogenizer for about 20 more seconds. The resulting cross-linked gelwas then placed in a FANN-50 rheometer for viscosity measurements. Inthe rheometer, a B5 extended bob was used, and the measurements weretaken at 95 rpm and at 140 degrees F. (60° C., 333 K). The viscositymeasurements for 10 minute intervals are shown in TABLE 2.

EXAMPLE 18

[0045] This example illustrates a procedure for on-the-fly making of a17.0 lb (8 kg) gel with a 30 second mixing of the guar powder andhydrating liquid. The results are also shown in TABLE 2. In thisexample, 1.02 g of New Guar 2 was hydrated in 500.0 ml of water forabout 30 seconds in a Waring blender at about 1200 rpm. About 1.25 mlsof borate cross-linking agent was then added to the fluid and furthermixed for about two minutes. The resulting cross-linked gel was thenplaced in a FANN-50 rheometer for viscosity measurements. In therheometer, a B5 extended bob was used, and the measurements were takenat 95 rpm and at 140 degrees F. (60° C., 333 K). The viscositymeasurements for 10 minute intervals and the amounts of cross-linkerused are shown in TABLE 2. From the results shown in TABLE 2, it may beseen that the New Guar 2 exhibits a high viscosity and a fast hydrationwith only 30 seconds of mixing in the Waring blender. For the sake ofcomparison, Example 11, which used New Guar 1, used the same procedureas this Example 18, except that Example 11 hydrated the guar powder inthe water for about 30 minutes in the Waring blender, instead of thehydration for about 30 seconds of Example 18. However, the resultingviscosities of Example 11 and 18 are similar.

[0046] Although the present invention and its advantages have beendescribed in detail, it should be understood that various changes,substitutions and alterations can be made herein without departing fromthe spirit and scope of the invention as defined by the appended claims.In particular, every range of values disclosed herein is to beunderstood as referring to the power set (the set of all subsets) of therespective range of values, in the sense of Georg Cantor. Accordingly,the protection sought herein is as set forth in the claims below.

I claim:
 1. A method of treating a subterranean formation using awell-treating fluid, the subterranean formation penetrated by awellbore, the method comprising: (A) preparing the well-treating fluidby admixing a fast-hydrating high-viscosity guar powder to a hydratingliquid to prepare the well-treating fluid; (B) hydrating the guarpowder; (C) admixing a cross-linker to the well-treating fluid; and (D)introducing the well-treating fluid to the wellbore at a temperature anda pressure sufficient to treat the subterranean formation.
 2. The methodof claim 1, wherein (A) further comprises admixing the guar powder in anamount comprising from about 0.05 to about 1.0 percent by weight of thehydrating liquid.
 3. The method of claim 1, wherein (A) furthercomprises admixing the guar powder in an amount comprising from about0.15 to about 0.3 percent by weight of the hydrating liquid.
 4. Themethod of claim 1, wherein the guar powder of (A) is selected from thegroup consisting of: (1) a de-polymerized fast-hydrating guar powder;(2) a derivative of the de-polymerized fast-hydrating guar powder; and(3) a derivative of the fast-hydrating high-viscosity guar powder. 5.The method of claim 4, wherein the derivative of the fast-hydratinghigh-viscosity guar powder and the derivative of the de-polymerizedfast-hydrating guar powder are selected from the group consisting of:(1) hydroxy propyl guar powder; (2) carboxy methyl guar powder; and (3)carboxy methyl hydroxy propyl guar powder.
 6. The method of claim 1,wherein (C) comprises using a cross-linker comprising a cross-linkingagent.
 7. The method of claim 6, wherein a delaying agent is admixed tothe well-treating fluid prior to the admixing of the cross-linker. 8.The method of claim 1, wherein (C) comprises using a cross-linkercomprising a cross-linking agent and a delaying agent.
 9. The method ofclaim 8, wherein the cross-linker is disposed to delay the cross-linkinguntil after the well-treating fluid is introduced into the wellbore. 10.The method of claim 8, wherein the cross-linking agent comprises fromabout 10.0 to about 40.0 percent by weight of the guar powder.
 11. Themethod of claim 8, wherein the cross-linking agent comprises from about20.0 to about 35.0 percent by weight of the guar powder.
 12. The methodof claim 8, wherein the delaying agent comprises from about 0.5 to about25.0 percent by weight of the guar powder.
 13. The method of claim 8,wherein the delaying agent comprises from about 2.0 to about 10.0percent by weight of the guar powder.
 14. The method of claim 1, wherein(C) further comprises admixing a delayed breaking agent to thewell-treating fluid.
 15. The method of claim 14, wherein (C) furthercomprises admixing the delayed breaking agent in an amount comprisingfrom about 0.01 to about 2.5 percent by weight of the hydrating liquid.16. The method of claim 14, wherein (C) further comprises admixing apropping agent to the well-treating fluid.
 17. The method of claim 1,wherein (C) further comprises admixing a propping agent to thewell-treating fluid.
 18. The method of claim 1, wherein (D) furthercomprises admixing a propping agent to the well-treating fluid beforeintroduction of the well-treating fluid into the wellbore.
 19. Themethod of claim 18, wherein (D) further comprises admixing a delayedbreaking agent to the well-treating fluid before introduction of thewell-treating fluid into the wellbore.
 20. The method of claim 19,wherein the delayed breaking agent is admixed in an amount comprisingfrom about 0.01 to about 2.5 percent by weight of the hydrating liquid.21. The method of claim 1, wherein (D) further comprises admixing adelayed breaking agent to the well-treating fluid before introduction ofthe well-treating fluid into the wellbore.
 22. The method of claim 21,wherein the delayed breaking agent is admixed in an amount comprisingfrom about 0.01 to about 2.5 percent by weight of the hydrating liquid.23. The method of claim 1, further comprising: (E) introducing abreaking agent to the wellbore, the breaking agent introduced after thesubterranean formation has been treated with the well-treating fluid.24. A well-treating fluid for use in treating subterranean formations,the well-treating fluid comprising: a hydrating liquid; a gelling agent,the gelling agent comprising a fast-hydrating high-viscosity guarpowder; and a cross-linker.
 25. The well-treating fluid of claim 24,wherein the guar powder comprises from about 0.05 to about 1.0 percentby weight of the hydrating liquid.
 26. The well-treating fluid of claim24, wherein the guar powder comprises from about 0.15 to about 0.3percent by weight of the hydrating liquid.
 27. The well-treating fluidof claim 24, wherein the guar powder is selected from the groupconsisting of: (1) a de-polymerized fast-hydrating guar powder; (2) aderivative of the de-polymerized fast-hydrating guar powder; and (3) aderivative of the fast-hydrating high-viscosity guar powder.
 28. Thewell-treating fluid of claim 27, wherein the derivative of thefast-hydrating high-viscosity guar powder and the derivative of thede-polymerized fast-hydrating guar powder are selected from the groupconsisting of: (1) hydroxy propyl guar powder; (2) carboxy methyl guarpowder; and (3) carboxy methyl hydroxy propyl guar powder.
 29. Thewell-treating fluid of claim 24, wherein the cross-linker comprises across-linking agent.
 30. The well-treating fluid of claim 29, whereinthe well-treating fluid further comprises a delaying agent.
 31. Thewell-treating fluid of claim 24, wherein the cross-linker comprises across-linking agent and a delaying agent.
 32. The well-treating fluid ofclaim 31, wherein the cross-linking agent comprises from about 10.0 toabout 40.0 percent by weight of the guar powder.
 33. The well-treatingfluid of claim 31, wherein the cross-linking agent comprises from about20.0 to about 35.0 percent by weight of the guar powder.
 34. Thewell-treating fluid of claim 31, wherein the delaying agent comprisesfrom about 0.5 to about 25.0 percent by weight of the guar powder. 35.The well-treating fluid of claim 31, wherein the delaying agentcomprises from about 2.0 to about 10.0 percent by weight of the guarpowder.
 36. The well-treating fluid of claim 24, wherein thewell-treating fluid further comprises a delayed breaking agent.
 37. Thewell-treating fluid of claim 36, wherein the delayed breaking agentcomprises from about 0.01 to about 2.5 percent by weight of thehydrating liquid.
 38. The well-treating fluid of claim 36, wherein thewell-treating fluid further comprises a propping agent.
 39. Thewell-treating fluid of claim 24, wherein the well-treating fluid furthercomprises a propping agent.
 40. A well-treating fluid for use intreating subterranean formations, the treatment comprising a fracturestimulation, the well-treating fluid comprising: a hydrating liquid; agelling agent, the gelling agent comprising a fast-hydratinghigh-viscosity guar powder; a cross-linker; and a propping agent. 41.The well-treating fluid of claim 40, wherein the guar powder comprisesfrom about 0.05 to about 1.0 percent by weight of the hydrating liquid.42. The well-treating fluid of claim 40, wherein the guar powdercomprises from about 0.15 to about 0.3 percent by weight of thehydrating liquid.
 43. The well-treating fluid of claim 40, wherein theguar powder is selected from the group consisting of: (1) ade-polymerized fast-hydrating guar powder; (2) a derivative of thede-polymerized fast-hydrating guar powder; and (3) a derivative of thefast-hydrating high-viscosity guar powder.
 44. The well-treating fluidof claim 43, wherein the derivative of the fast-hydrating high-viscosityguar powder and the derivative of the de-polymerized fast-hydrating guarpowder are selected from the group consisting of: (1) hydroxy propylguar powder; (2) carboxy methyl guar powder; and (3) carboxy methylhydroxy propyl guar powder.
 45. The well-treating fluid of claim 40,wherein the cross-linker comprises a cross-linking agent.
 46. Thewell-treating fluid of claim 45, wherein the well-treating fluid furthercomprises a delaying agent.
 47. The well-treating fluid of claim 40,wherein the cross-linker comprises a cross-linking agent and a delayingagent.
 48. The well-treating fluid of claim 47, wherein thecross-linking agent comprises from about 10.0 to about 40.0 percent byweight of the guar powder.
 49. The well-treating fluid of claim 47,wherein the cross-linking agent comprises from about 20.0 to about 35.0percent by weight of the guar powder.
 50. The well-treating fluid ofclaim 47, wherein the delaying agent comprises from about 0.5 to about25.0 percent by weight of the guar powder.
 51. The well-treating fluidof claim 47, wherein the delaying agent comprises from about 2.0 toabout 10.0 percent by weight of the guar powder.
 52. The well-treatingfluid of claim 40, wherein the well-treating fluid further comprises adelayed breaking agent.
 53. The well-treating fluid of claim 52, whereinthe delayed breaking agent comprises from about 0.01 to about 2.5percent by weight of the hydrating liquid.
 54. A well-treating fluid foruse in treating subterranean formations, the treatment comprising afracture stimulation, the well-treating fluid comprising: a hydratingliquid; a gelling agent, the gelling agent comprising a fast-hydratinghigh-viscosity guar powder; a cross-linker, the cross-linker comprisinga cross-linking agent and a delaying agent; a delayed breaking agent;and a propping agent.
 55. The well-treating fluid of claim 54, whereinthe guar powder further comprises from about 0.05 to about 1.0 percentby weight of the hydrating liquid.
 56. The well-treating fluid of claim54, wherein the guar powder further comprises from about 0.15 to about0.3 percent by weight of the hydrating liquid.
 57. The well-treatingfluid of claim 54, wherein the guar powder is selected from the groupconsisting of: (1) a de-polymerized fast-hydrating guar powder; (2) aderivative of the de-polymerized fast-hydrating guar powder; and (3) aderivative of the fast-hydrating high-viscosity guar powder.
 58. Thewell-treating fluid of claim 57, wherein the derivative of thefast-hydrating high-viscosity guar powder and the derivative of thede-polymerized fast-hydrating guar powder are selected from the groupconsisting of: (1) hydroxy propyl guar powder; (2) carboxy methyl guarpowder; and (3) carboxy methyl hydroxy propyl guar powder.
 59. Thewell-treating fluid of claim 54, wherein the cross-linking agentcomprises from about 10.0 to about 40.0 percent by weight of the guarpowder.
 60. The well-treating fluid of claim 54, wherein thecross-linking agent comprises from about 20.0 to about 35.0 percent byweight of the guar powder.
 61. The well-treating fluid of claim 54,wherein the delaying agent comprises from about 0.5 to about 25.0percent by weight of the guar powder.
 62. The well-treating fluid ofclaim 54, wherein the delaying agent comprises from about 2.0 to about10.0 percent by weight of the guar powder.
 63. The well-treating fluidof claim 54, wherein the delayed breaking agent comprises from about0.01 to about 2.5 percent by weight of the hydrating liquid.
 64. Amethod of treating a subterranean formation using a well-treating fluid,the subterranean formation penetrated by a wellbore, the methodcomprising: (A) preparing the well-treating fluid by admixing afast-hydrating high-viscosity guar powder to a hydrating liquid toprepare the well-treating fluid; (B) hydrating the guar powder; (C)admixing a cross-linker and a delayed breaking agent to thewell-treating fluid; and (D) introducing the well-treating fluid to thewellbore at a temperature and a pressure sufficient to treat thesubterranean formation.
 65. The method of claim 64, wherein (A) furthercomprises admixing the guar powder in an amount comprising from about0.05 to about 1.0 percent by weight of the hydrating liquid.
 66. Themethod of claim 64, wherein (A) further comprises admixing the guarpowder in an amount comprising from about 0.15 to about 0.3 percent byweight of the hydrating liquid.
 67. The method of claim 64, wherein theguar powder of (A) is selected from the group consisting of: (1) ade-polymerized fast-hydrating guar powder; (2) a derivative of thede-polymerized fast-hydrating guar powder; and (3) a derivative of thefast-hydrating high-viscosity guar powder.
 68. The method of claim 67,wherein the derivative of the fast-hydrating high-viscosity guar powderand the derivative of the de-polymerized fast-hydrating guar powder areselected from the group consisting of: (1) hydroxy propyl guar powder;(2) carboxy methyl guar powder; and (3) carboxy methyl hydroxy propylguar powder.
 69. The method of claim 64, wherein (C) comprises using across-linker comprising a cross-linking agent.
 70. The method of claim69, wherein a delaying agent is admixed to the well-treating fluid priorto the admixing of the cross-linker.
 71. The method of claim 64, wherein(C) comprises using a cross-linker comprising a cross-linking agent anda delaying agent.
 72. The method of claim 71, wherein the cross-linkeris disposed to delay the cross-linking until after the well-treatingfluid is introduced into the wellbore.
 73. The method of claim 71,wherein the cross-linking agent comprises from about 10.0 to about 40.0percent by weight of the guar powder.
 74. The method of claim 71,wherein the cross-linking agent comprises from about 20.0 to about 35.0percent by weight of the guar powder.
 75. The method of claim 71,wherein the delaying agent comprises from about 0.5 to about 25.0percent by weight of the guar powder.
 76. The method of claim 71,wherein the delaying agent comprises from about 2.0 to about 10.0percent by weight of the guar powder.
 77. The method of claim 64,wherein (C) further comprises admixing the delayed breaking agent in anamount comprising from about 0.01 to about 2.5 percent by weight of thehydrating liquid.
 78. The method of claim 64, wherein (C) furthercomprises admixing a propping agent to the well-treating fluid.
 79. Themethod of claim 64, wherein (D) further comprises admixing a proppingagent to the well-treating fluid.
 80. A method of performing a fracturetreatment in a subterranean formation using a well-treating fluid, thesubterranean formation penetrated by a wellbore, the method comprising:(A) preparing the well-treating fluid by admixing a fast-hydratinghigh-viscosity guar powder to a hydrating liquid to prepare thewell-treating fluid; (B) hydrating the guar powder; (C) admixing across-linker and a propping agent to the well-treating fluid; and (D)introducing the well-treating fluid to the wellbore at a temperature anda pressure sufficient to stimulate the fracture treatment of thesubterranean formation.
 81. The method of claim 80, wherein (A) furthercomprises admixing the guar powder in an amount comprising from about0.05 to about 1.0 percent by weight of the hydrating liquid.
 82. Themethod of claim 80, wherein (A) further comprises admixing the guarpowder in an amount comprising from about 0.15 to about 0.3 percent byweight of the hydrating liquid.
 83. The method of claim 80, wherein theguar powder of (A) is selected from the group consisting of: (1) ade-polymerized fast-hydrating guar powder; (2) a derivative of thede-polymerized fast-hydrating guar powder; and (3) a derivative of thefast-hydrating high-viscosity guar powder.
 84. The method of claim 83,wherein the derivative of the fast-hydrating high-viscosity guar powderand the derivative of the de-polymerized fast-hydrating guar powder areselected from the group consisting of: (1) hydroxy propyl guar powder;(2) carboxy methyl guar powder; and (3) carboxy methyl hydroxy propylguar powder.
 85. The method of claim 80, wherein (C) comprises using across-linker comprising a cross-linking agent.
 86. The method of claim85, wherein a delaying agent is admixed to the well-treating fluid priorto the admixing of the cross-linker.
 87. The method of claim 80, wherein(C) comprises using a cross-linker comprising a cross-linking agent anda delaying agent.
 88. The method of claim 87, in which the cross-linkeris disposed to delay the cross-linking until after the well-treatingfluid is introduced into the wellbore.
 89. The method of claim 87,wherein the delaying agent comprises from about 0.5 to about 25.0percent by weight of the guar powder.
 90. The method of claim 87,wherein the delaying agent comprises from about 2.0 to about 10.0percent by weight of the guar powder.
 91. The method of claim 87,wherein the cross-linking agent comprises from about 10.0 to about 40.0percent by weight of the guar powder.
 92. The method of claim 87,wherein the cross-linking agent comprises from about 20.0 to about 35.0percent by weight of the guar powder.
 93. The method of claim 80,wherein (C) further comprises admixing a delayed breaking agent to thewell-treating fluid.
 94. The method of claim 93, wherein (C) furthercomprises admixing the delayed breaking agent in an amount comprisingfrom about 0.01 to about 2.5 percent by weight of the hydrating liquid.95. The method of 80, further comprising: (E) introducing a breakingagent to the wellbore.
 96. A method of performing a fracture treatmentto a subterranean formation using a well-treating fluid, thesubterranean formation penetrated by a wellbore, the method comprising:(A) preparing the well-treating fluid by admixing a fast-hydratinghigh-viscosity guar powder to a hydrating liquid to prepare thewell-treating fluid; (B) hydrating the guar powder; (C) admixing across-linker, a propping agent, and a delayed breaking agent to thewell-treating fluid, wherein the cross-linker comprises a delaying agentand a cross-linking agent, and wherein the cross-linker is disposed todelay the cross-linking until after the well-treating fluid isintroduced to the wellbore; (D) introducing the well-treating fluid tothe wellbore at a temperature and a pressure sufficient to stimulate thefracture treatment of the subterranean formation; and (E) breaking thewell-treating fluid with the delayed breaking agent, the delayedbreaking agent disposed to delay breaking of the well-treating fluiduntil after stimulation of the fracture treatment.
 97. The method ofclaim 96, wherein (A) further comprises admixing the guar powder in anamount comprising from about 0.05 to about 1.0 percent by weight of thehydrating liquid.
 98. The method of claim 96, wherein (A) furthercomprises admixing the guar powder in an amount comprising from about0.15 to about 0.3 percent by weight of the hydrating liquid.
 99. Themethod of claim 96, wherein the guar powder of (A) is selected from thegroup consisting of: (1) a de-polymerized fast-hydrating guar powder;(2) a derivative of the de-polymerized fast-hydrating guar powder; and(3) a derivative of the fast-hydrating high-viscosity guar powder. 100.The method of claim 99, wherein the derivative of the fast-hydratinghigh-viscosity guar powder and the derivative of the de-polymerizedfast-hydrating guar powder are selected from the group consisting of:(1) hydroxy propyl guar powder; (2) carboxy methyl guar powder; and (3)carboxy methyl hydroxy propyl guar powder.
 101. The method of claim 96,wherein the cross-linking agent comprises from about 10.0 to about 40.0percent by weight of the guar powder.
 102. The method of claim 96,wherein the cross-linking agent comprises from about 20.0 to about 35.0percent by weight of the guar powder.
 103. The method of claim 96,wherein the delaying agent comprises from about 0.5 to about 25.0percent by weight of the guar powder.
 104. The method of claim 96,wherein the delaying agent comprises from about 2.0 to about 10.0percent by weight of the guar powder.
 105. The method of claim 96,wherein (C) further comprises admixing the delayed breaking agent in anamount comprising from about 0.01 to about 2.5 percent by weight of theguar powder.